CN110821486A - A Calculation Method for Physical Properties Parameters of Reservoir Predominant Channel - Google Patents

Abstract

The invention discloses a method for calculating physical property parameters of a reservoir dominant channel, which comprises the following steps: step 1, determining the distribution of large pore channel positions; step 2, calculating the pore size distribution; step 3, calculating the transverse heterogeneity of the flowing water area; step 4, calculating the volume of each level of pore channel; and 5, simulating and calculating the fractured reservoir. The invention has the advantages that: the size and the volume of each level of pore canal in the water drive area are accurately calculated, the prior art is only limited to identifying the dominant channel existing between wells, and the calculation of the volume of each level of channel is not involved.

Description

A Calculation Method for Physical Properties Parameters of Reservoir Predominant Channel

technical field

The invention relates to the technical field of oil and gas field development, in particular to a method for calculating physical property parameters of reservoir dominant channels.

Background technique

During the long-term waterflooding development of oilfields, due to the long-term immersion and scouring of the reservoir by the injected water, the fluid properties, dynamic characteristics and physical properties of the reservoir will be significantly changed, resulting in the existence of dominant seepage channels between oil and water wells, resulting in an ineffective circulation of water injection. Affect oilfield recovery. The current research on the dominant channel is mainly based on the qualitative identification of the dominant channel, such as the direct method of mine data, the identification method of production dynamic data, the tracer monitoring method, and there is a lack of an effective method to calculate the volume and physical parameters of the dominant channel. Based on the oil and gas layer seepage mechanics theory, the invention proposes a method for calculating the physical property parameters of dominant channels by relying on conventional dynamic and static data on site, and provides a theoretical basis for deep profile control or well pattern adjustment measures in the middle and late stages of oilfield development.

SUMMARY OF THE INVENTION

Aiming at the defects of the prior art, the present invention provides a method for calculating the physical property parameters of the reservoir dominant channel, which can effectively solve the above-mentioned problems in the prior art.

In order to realize the above purpose of the invention, the technical scheme adopted by the present invention is as follows:

A method for calculating physical property parameters of a reservoir dominant channel, comprising the following steps:

Step 1, the determination of the location distribution of the large pores;

In the control area of a pair of injection-production wells with homogeneous, equal thickness and single-production layer, the industrial oil recovery factor of crude oil reaches B% and the water cut of production wells reaches A% after time t is put into production. Note the water injection well point O, the production well point W, the pressure gradient near the line segment OW is the largest, with OE and OF as the length units, by

Determine the parameter α, the curve

y=x ^α (x∈[0,1])

It is the lower boundary of the high permeability zone, and the upper and lower boundaries are symmetrical about the diagonal OW. In this way, the distribution position of large pore channels is calculated and simulated. For heterogeneous formations, the distribution area of large pore channels is determined by using data such as reservoir description results and water absorption profiles, and its area is equal to B%, which is reflected in the injection-production well control area. , the crude oil in the area of B% has been produced, this area contains the dominant seepage channel, the crude oil is basically displaced, the seepage fluid in the channel is water, and the crude oil in the area of (1-B%) has not been recovered. out.

Different α values correspond to different lower boundary curves, which also correspond to different distribution areas of high-permeability strips. For non-five-point well patterns, the midpoint of the line connecting the left and right adjacent wells is used to determine the control area, and the area is denoted as S ₁ . _The recovery degree inside is still recorded as B%, and the α1 corresponding to the lower boundary curve satisfies the equation:

Step 2, calculation of pore size distribution;

Suppose the reservoir is divided into n layers according to vertical heterogeneity, and at a certain time in the later stage of water injection production, according to the water absorption profile, water absorption index, and liquid extraction index, the actual recovery factor B _i % of each layer can be determined by splitting, i=1 ,2,…,n.

If there is lateral inhomogeneity, the flow area roughly drawn in the i-th layer is still recorded as B _i , so that it includes the position with high permeability, and its volume is equal to B _i % of the total volume of the layer; if there is no lateral inhomogeneity, Then draw B _i , whose area is equal to B _i % of the total area of the layer, and the water-oil flow ratio of the i-th layer

A _i is the moisture content of the i-th layer produced liquid, and

Here K _io , μ _o , μ _w , and B _i % are all known, and the water permeability of the i-th layer can be calculated at this time

Average radius of flooded pores in this layer

where φ _iw is the porosity in the swept region of injected water. If K is in Darcy and r is in centimeters, there is an approximate formula

The average pore size of the remaining unwatered parts is

remember

That is, λ _i represents the ratio of the pore radius in the area where the water flows through the i-th layer and the area where the oil flows, and the pore radius obeys the log-normal distribution and approximately obeys the normal distribution.

即

which is

Among them, the standard deviation σio of the pore throat radius of the i-th undisturbed formation is calculated by formula (11).

The radius of the hole can be divided into several levels according to the needs.

The grading of ducts and their division criteria are determined according to the geological conditions and engineering needs.

In the absence of special consideration, the principle of pore size classification is that the probability of pore size calculated for most of the one-injection-one-mining control areas belongs to each level is appropriate, and there will be no situation where the probability of one or two levels is particularly high or low. .

The control area of a well group is subdivided with a 3D mesh, and the point falling in B _i corresponds to the pore throat radius

where: σ _iw =λ _i σ _io (13)

Calculate the probability that r _iw belongs to the above-mentioned level, divide the [0,1] interval into k sub-intervals according to the probability value, and the length corresponds to the probability value.

Generate a random number X uniformly distributed in the [0,1] interval. If X falls in the kth sub-interval, the pore throat radius at this point is the kth level, and this point is marked with the kth mark.

Step 3, the calculation of the lateral heterogeneity of the flow area;

Divide the interval [0, R _e ] of one note and one mining unit into 100 equal parts;

Each area is regarded as a one-way flow of incompressible fluid, and the flow of each part is different on the macroscopic level. These 100 parts together constitute the flow between one injection and one production well. The flow formula for the jth part of Darcy's law is:

In the formula, A _j — the cross-sectional area of the J-th water passage, m ² ;

K _j — permeability, md;

ΔP _j ——pressure difference across the jth part, mPa;

Q _j ——the flow of the jth share, m ³ /month;

L——the length of each small part, the well spacing _Re /100, m;

μ——viscosity, mPa s;

a——unit correction coefficient, a=0.3858.

From this, the permeability at the jth part can be obtained

Formula (15) shows that the permeability can be obtained for the known pressure difference, seepage cross-sectional area and flow rate. The calculation methods of pressure difference, seepage cross-sectional area and flow rate are described below to obtain the permeability of each place.

1. Calculation of flow

Using the linear combination of the monthly water absorption Q1 of the _jth layer of the injection well and the monthly liquid production _Q2 of the production well corresponding to this layer, the liquid flow rate Q _i in the ith part can be obtained

2. Calculation of pressure everywhere

Water is injected in Well A and liquid is produced in Well B, the pressure at any point M of the formation can be determined by deduction as

in

where r ₁ ——the distance from point M to injection well A;

r ₂ ——the distance from point M to production well B;

r _e ——supply radius;

r _w — wellbore radius;

R - well spacing.

p _WA and p _WB are the water injection in well A and the liquid production in well B at the same time, and the bottom hole pressure of the two wells.

3. How to find the cross-sectional area A

Let the circle of radius r intersect the curve y=x ^α at the point (x, y), and solve the system of equations

You can get the intersection coordinates (x, y). Therefore, β=tan ^-1 (y/x) can be obtained, so θ=π/2 -2β, and the thickness of the reservoir is set to be h, then the cross-sectional area of water passing at the radius r is

Substitute the cross-sectional area A, Δp, flow rate Q _i and other values into equation (15) to obtain the permeability K at the cross-section with radius r, and then use the method described in the previous paragraph to calculate the probability that the pore throat radius belongs to each order.

Step 4, the calculation of the pore volume at all levels;

After quantitatively analyzing the position and size distribution of the large channels, the volume of the channels at all levels should be calculated. The calculation process of the volume of the channels at each level is as follows: _Re represents the distance between the water injection well O and the oil production well W, Let the circle of radius r intersect the curve y=a ^1-α x ^α at (x, y), and solve the system of equations

Obtain (x _r , y _r ), tgβ=(x _r /a) ^α-1 , β=tan ⁻¹ ((x _r /a) ^α-1 ), θ=π/2-2β, the area of sector AOB For S _AOB =πθr ² /2, the area of the figure enclosed by the straight line y=xtgβ and the curve y=a ^1-α x ^α

The area of the large pore distribution area in a circle of radius r is

Assume that the distribution probabilities of super-large pore, large pore, medium pore and small pore at radius r are respectively p ₁ (r), p ₂ (r), p ₃ (r), p ₄ (r), and the interval [0 , R _e ] 100 equal parts, the interval is R _e /n, the i-level pore volume of the rth part can be obtained

in,

得到。x _r by solving the system of equations

get.

Step 5. Simulation calculation of fractured reservoir

Calculate the permeability K and porosity φ of each of the 100 parts of the flowing water area. On this basis, through the formula

where b _i — crack width, mm;

——第i份的裂缝渗透率，D；

——fracture permeability of the ith part, D;

——第i份的裂缝孔隙度。

——fracture porosity of the i-th part.

近似用原软件算出的K_i代替，这是因为裂缝渗透率远大于基质渗透率，即认为水都是沿裂缝窜流过去；Calculate the fracture width b _i of the ith part, where the fracture permeability of the ith part

It is approximately replaced by the K _i calculated by the original software, because the fracture permeability is much larger than the matrix permeability, that is, it is considered that the water is channeled along the fracture;

and is the measured data, in the case of no measured data, use the following method to determine

Firstly, the porosity and permeability of the three well groups should be fitted according to the following formula.

φ=αlnK+β

that is

K=Ae ^Bφ (28)

K(mD)，φ为去掉％的数值。in,

K(mD), φ is the value with % removed.

The relationship between fracture permeability and porosity can be expressed by the following formula

K _f = 8.33×10 ⁶ φ _f w ² (29)

Among them, w——crack width, mm.

K _f ——fracture permeability, D;

Set aK=K _f (a is determined by the water content, where a is approximately taken as 0.5), then from equations (28) and (29), and paying attention to the dimensional changes, we can get

aAe ^Bφ = 8.33×10 ⁵ φ _f w ² (30)

代入(30)式remember

Substitute into (30) formula

The calculation formula of the known slit width w and hole radius r is as follows

用对孔隙介质算出的孔径分布可求裂缝介质的缝宽分布，即各种缝宽的裂缝所占的百分比。In formula (32), K is the fracture permeability, and in formula (33), K is the permeability of the high-permeability zone that needs to be plugged and calculated according to the void medium. Because now

Using the pore size distribution calculated for the porous medium, the fracture width distribution of the fractured medium can be obtained, that is, the percentage of fractures with various fracture widths.

Slit width to hole radius ratio

是地质资料提供的渗流介质综合孔隙度φ的1％，平均缝宽是平均孔隙半径的1.21倍。对应于孔径划分以3， 5，8为限，缝宽则以3.6，6.1，9.7为界，即各级裂缝对应缝宽范围如下(μm)：porosity of fractured media

It is 1% of the comprehensive porosity φ of the seepage medium provided by the geological data, and the average fracture width is 1.21 times the average pore radius. Corresponding to the aperture division is limited to 3, 5, and 8, and the fracture width is limited to 3.6, 6.1, and 9.7, that is, the corresponding fracture width range of each level of fracture is as follows (μm):

Micro-cracks: w≤3.6;

Medium crack: 3.6≤w≤6.1;

Wide crack: 6.1≤w≤9.7;

Extra wide crack: w≥9.7.

According to the above classification criteria, the above method is used to calculate, in the calculation result data table, the volume and percentage of each level of cracks are listed in detail.

Compared with the prior art, the advantage of the present invention is that the size and volume of the channels at all levels in the water flooding area can be accurately calculated. The prior technology is only limited to identifying the dominant channels existing between wells, and does not involve the volume of the channels at all levels. calculate.

Description of drawings

Fig. 1 is the schematic diagram of the five-spot well pattern high-permeability strip distribution area according to the embodiment of the present invention;

Fig. 2 is the schematic diagram of the distribution area of non-five-spot well pattern high-permeability strips according to the embodiment of the present invention;

Fig. 3 is the normal density function diagram of the embodiment of the present invention;

Fig. 4 is the schematic diagram of one injection and one extraction unit equal division according to the embodiment of the present invention;

Fig. 5 is the pressure distribution diagram of the first embodiment of the present invention during injection and production;

6 is a schematic diagram of the cross-sectional area A of the embodiment of the present invention;

FIG. 7 is a schematic diagram of dividing the [0,1] interval into four sub-intervals according to four probability values according to an embodiment of the present invention.

Detailed ways

In order to make the objectives, technical solutions and advantages of the present invention more clear, the following examples are given to further illustrate the present invention.

A method for calculating physical property parameters of a reservoir dominant channel, comprising the following steps:

Step 1, the determination of the location distribution of the large pores;

In the control area of a pair of injection-production wells in a homogeneous, equal-thickness, single-production layer, the crude oil recovery degree is B% after the time t is put into production, and the water cut of the production wells reaches A%. As shown in Figure 1, note the point O of the water injection well, the point W of the production well, and the pressure gradient near the line segment OW is the largest, with OE and OF as the length units, by

Determine the parameter α, the curve

y=x ^α (x∈[0,1])

It is the lower boundary of the high permeability zone, and the upper and lower boundaries are symmetrical about the diagonal OW. In this way, the distribution position (equivalent area) of the large pores is calculated and simulated, as shown in the shaded part in Figure 1. For heterogeneous formations, use the reservoir description results and water absorption profiles to determine the distribution area of large pores, and its area (multiplied by the thickness is the volume) is equal to B%, which is reflected in the injection-production well control area, and the area of B% The crude oil in the pore has been produced, this area contains the dominant seepage channel, the crude oil is basically displaced, the seepage fluid in the pore channel is water, and the crude oil in the area (1-B%) has not been produced.

Different α values correspond to different lower boundary curves, which also correspond to different distribution areas of high-permeability strips. For non-five-point well patterns, use the midpoint of the line connecting the left and right adjacent wells to determine the control area (Fig. 2), and the area is recorded as S ₁ , the recovery degree in it is still recorded as B%, and the α ₁ corresponding to the lower boundary curve satisfies the equation:

Step 2, calculation of pore size distribution;

Assuming that the reservoir is divided into n layers according to vertical heterogeneity, such as the upper, middle and lower layers, n=3. Assuming a certain time in the later stage of water injection production, according to the water absorption profile, water absorption index, and liquid extraction index, the actual recovery factor B _i % of each layer can be determined by splitting, i=1,2,...,n.

If there is lateral inhomogeneity, the flow area roughly drawn in the i-th layer is still recorded as B _i , so that it includes the position with high permeability, and its volume is equal to B _i % of the total volume of the layer; if there is no lateral inhomogeneity, Then draw B _i as shown in Figure 1, and its area is equal to B _i % of the total area of the layer, and the water-oil flow ratio of the i-th layer

A _i is the moisture content of the i-th layer produced liquid, and

Here K _io , μ _o , μ _w , and B _i % are all known, and the water permeability of the i-th layer can be calculated at this time

Average radius of flooded pores in this layer

where φ _iw is the porosity of the flowing water part. If K is in Darcy and r is in centimeters, there is an approximate formula

The average pore size of the remaining unwatered parts is

remember

That is, λ _i represents the ratio of the pore radius at the i-th layer of flowing water and flowing oil. It can be seen from the textbook "Reservoir Physics" that the pore radius obeys the log-normal distribution and approximately obeys the normal distribution.

即

which is

Among them, the standard deviation σio of the pore throat radius of the i-th undisturbed formation is measured by mercury intrusion experiment, and can also be obtained by core slice measurement statistics, or estimated by permeability variation coefficient, and can also be calculated by formula (11).

The radius of the hole can be divided into several levels according to the needs, such as

Large pore channel: Rw≥8μm;

Large pores: Rw∈[5μm,8μm];

Mesoporous channel: Rw∈[3μm,5μm];

Small pores: Rw≤3μm.

The pore channel classification and its classification standard are generally determined according to the geological conditions (such as whether sand production) and engineering needs (such as considering the particle size of the plugging agent). For example, if no sand is seen in the production well, it is basically judged that the pore structure of the formation has not undergone major changes, and the slug structure is not intended to be complicated. Refer to Table 1 to properly estimate the value range of the apertures at all levels.

In the absence of special consideration (for example, a specified range is customized to one level for a certain need), the principle of aperture classification is that the probability of apertures calculated for most of the one-note-one-mining control areas belongs to each level is more appropriate, and will not appear A situation where the probability of one or two levels is particularly high or low. As shown in Figure 3, if the grading points are taken as 5, 10, and 15, there will be no large pores and super-large pore channels in most well areas; similarly, if the grading points are taken as 1, 2, and 3, there will be basically all large and super-large pores. , which does not achieve the purpose of being divided into 4 levels.

Table 1 Correspondence table of porosity, permeability and pore size

The control area of a well group is subdivided with a 3D mesh, and the point falling in B _i corresponds to the pore throat radius

where: σ _iw =λ _i σ _io (13)

Calculate the probability that r _iw belongs to the above 4 levels, divide the [0,1] interval into 4 sub-intervals according to 4 probability values, and the length corresponds to 4 probability values, as shown in Figure 7.

Generate a random number X uniformly distributed in the [0,1] interval. If X falls in the kth sub-interval, the pore throat radius at this point is the kth level. For the sake of intuition, this point is marked with the kth mark, such as using a color . In this way, the connectivity of large pores is calculated, analyzed and observed.

Step 3, the calculation of the lateral heterogeneity of the flow area;

When water injection is used for production, the pressure gradient in the reservoir is different. For example, the pressure gradient near the wellbore is large, and the scouring ability of water on the formation is also large, which is more likely to lead to the formation of large pores. The further analysis and calculation are as follows.

Divide the interval [0, R _e ] of one note and one mining unit into 100 equal parts, that is, the interval [O, W] 100 in the schematic diagram 4 is divided into equal parts, and the interval is _Re /100.

Each area is regarded as a one-way flow of incompressible fluid, and the flow of each part is different on the macroscopic level. These 100 parts together constitute the flow between one injection and one production well. The flow formula for the jth part of Darcy's law is:

In the formula, A _j — the cross-sectional area of the J-th water passage, m ² ;

K _j — permeability, md;

ΔP _j ——pressure difference across the jth part, mPa;

Q _j ——the flow of the jth share, m ³ /month;

L——the length of each small part, the well spacing _Re /100, m;

μ——viscosity, mPa s;

a——unit correction coefficient, a=0.3858.

From this, the permeability at the jth part can be obtained

Formula (15) shows that the permeability can be obtained for the known pressure difference, seepage cross-sectional area and flow rate. The calculation methods of pressure difference, seepage cross-sectional area and flow rate are described below to obtain the permeability of each place.

1. Calculation of flow

Using the linear combination of the monthly water absorption Q1 of the _jth layer of the injection well and the monthly liquid production _Q2 of the production well corresponding to this layer, the liquid flow rate Q _i in the ith part can be obtained

2. Calculation of pressure everywhere

As shown in Fig. 5, if well A injects water while well B produces liquid, the pressure at any point M of the formation can be determined by deduction as

in

where r ₁ ——the distance from point M to injection well A;

r ₂ ——the distance from point M to production well B;

r _e ——supply radius;

r _w — wellbore radius;

R - well spacing.

p _WA and p _WB are the water injection in well A and the liquid production in well B at the same time, and the bottom hole pressure of the two wells.

3. How to find the cross-sectional area A

As shown in Figure 6, let the circle with radius r intersect the curve y=x ^α at point (x, y), and solve the equation system

You can get the intersection coordinates (x, y). Therefore, β=tan ^-1 (y/x) can be obtained, so θ=π/2 -2β, and the thickness of the reservoir is set to be h, then the cross-sectional area of water passing at the radius r is

Substitute the cross-sectional area A, Δp, flow rate Q _i and other values into equation (15) to obtain the permeability K at the cross-section with radius r, and then use the method described in the previous paragraph to calculate the probability that the pore throat radius belongs to each order.

Step 4, the calculation of the pore volume at all levels;

After quantitatively analyzing the position and size distribution of the large pore channels, the volume of the pore channels at each level should be calculated. The calculation process of the pore channel volume at each level is as follows: As shown in Figure 6, _Re represents the distance between the water injection well O and the oil production well W, Let the circle of radius r intersect the curve y=a ^1-α x ^α at (x, y), and solve the system of equations

Obtain (x _r , y _r ), tgβ=(x _r /a) ^α-1 , β=tan ⁻¹ ((x _r /a) ^α-1 ), θ=π/2-2β, the area of sector AOB For S _AOB =πθr ² /2, the area of the figure enclosed by the straight line y=xtgβ and the curve y=a ^1-α x ^α

The area of the large pore distribution area in a circle of radius r is

Assume that the distribution probabilities of super-large pore, large pore, medium pore and small pore at radius r are respectively p ₁ (r), p ₂ (r), p ₃ (r), p ₄ (r), and the interval [0 , R _e ] 100 equal parts, the interval is R _e /n, the i-level pore volume of the rth part can be obtained

in,

x _r by solving the system of equations get.

Step 5. Simulation calculation of fractured reservoir

The original software has been able to calculate the permeability K and porosity φ of each of the 100 parts of the flowing water area. On this basis, through the formula

where b _i — crack width, mm;

——第i份的裂缝渗透率，D；

——fracture permeability of the ith part, D;

——第i份的裂缝孔隙度。

——fracture porosity of the i-th part.

近似用原软件算出的K_i代替，这是因为裂缝渗透率远大于基质渗透率，即认为水都是沿裂缝窜流过去；而

是实测数据，在没有实测数据的情况下，用下面的方法确定

Calculate the fracture width b _i of the ith part, where the fracture permeability of the ith part

It is approximately replaced by the K _i calculated by the original software, because the fracture permeability is much larger than the matrix permeability, that is to say, it is considered that the water is channeled along the fracture;

is the measured data, in the case of no measured data, use the following method to determine

First, the porosity and permeability of the three well groups should be fitted according to the following equations.

φ=αlnK+β

that is

K=Ae ^Bφ (28)

K(mD)，φ为去掉％的数值。in,

K(mD), φ is the value with % removed.

The fitting and calculation results are shown in Table 2.

Table 2 Fitting parameter table

According to "Reservoir Physics", the relationship between fracture permeability and porosity can be expressed by the following formula

K _f = 8.33×10 ⁶ φ _f w ² (29)

Among them, w——crack width, mm.

K _f ——fracture permeability, D;

Set aK=K _f (a is determined by the water content, where a is approximately taken as 0.5), then from equations (28) and (29), and paying attention to the dimensional changes, we can get

aAe ^Bφ = 8.33×10 ⁵ φ _f w ² (30)

代入(30)式remember

Substitute into (30) formula

Among them, the porosity of three well groups is 17.8%. Because the fracture width generally varies from 2 μm to 10 μm, when w = 2 μm, the calculated x values of the three well groups F247, G198, and J226 are equal to 0.2998, 0.3331, and 0.0030, respectively; when w = 5 μm, the calculated three The x values of the three well groups are respectively equal to 0.04797, 0.05330, and 0.00047; when w = 10 μm, the calculated x values of the three well groups are equal to 0.01199, 0.01332, and 0.00012, respectively. Then the average values of the three well groups x are 0.1199, 0.13324, and 0.00359, respectively, and 0.01, which is the closest to the empirically estimated value, is taken as the approximate value of x, that is, φ _f = 0.01φ.

The calculation formula of the known slit width w and hole radius r is as follows

In formula (32), K is the fracture permeability, and in formula (33), K is the permeability of the high-permeability zone that needs to be plugged and calculated according to the void medium. Because now K _fi =K _i , and 0.01φ _i =φ _fi , the pore size distribution calculated for the porous medium can be used to obtain the fracture width distribution of the fractured medium, that is, the percentage of fractures with various fracture widths. Slit width to hole radius ratio

是地质资料提供的渗流介质综合孔隙度φ的1％，平均缝宽是平均孔隙半径的1.21倍，于是在孔隙介质高渗条带模拟计算的基础上，可以方便地换算到裂缝分布的描述情形。对应于孔径划分以3，5，8为限，缝宽则以3.6，6.1，9.7为界，即各级裂缝对应缝宽范围如下(μm)：That is, the porosity of the fractured media

It is 1% of the comprehensive porosity φ of the seepage medium provided by the geological data, and the average fracture width is 1.21 times the average pore radius. Therefore, on the basis of the simulation calculation of the high-permeability strip in the porous medium, it can be easily converted to the description of the fracture distribution. . Corresponding to the aperture division is limited to 3, 5, 8, and the fracture width is limited to 3.6, 6.1, 9.7, that is, the corresponding fracture width range of each level of fracture is as follows (μm):

Micro cracks: w≤3.6;

Medium crack: 3.6≤w≤6.1;

Wide crack: 6.1≤w≤9.7;

Extra wide crack: w≥9.7.

According to the above classification criteria, the above method is used to calculate, in the calculation result data table, the volume and percentage of each level of cracks are listed in detail.

Those of ordinary skill in the art will appreciate that the embodiments described herein are intended to help readers understand the implementation method of the present invention, and it should be understood that the protection scope of the present invention is not limited to such specific statements and embodiments. Those skilled in the art can make various other specific modifications and combinations without departing from the essence of the present invention according to the technical teaching disclosed in the present invention, and these modifications and combinations still fall within the protection scope of the present invention.

Claims (1)

1. A reservoir dominant channel physical property parameter calculation method is characterized by comprising the following steps:

step 1, determining the distribution of large pore channel positions;

in a pair of injection and production well control areas of a homogeneous, equal-thickness and single-production layer, the crude oil industrial recovery rate reaches B% and the water content of a production well reaches A% after the time t from production; recording a water injection well point O, a production well as a point W, the pressure gradient near a line segment OW is maximum, and taking OE and OF as length units, the method comprises

Determination of the parameter α, Curve

y＝x^α(x∈[0,1])

The lower boundary of the high permeability zone, the upper boundary and the lower boundary being symmetric about the diagonal OW; thus, the distribution position of the large pore channel is calculated and simulated, for the heterogeneous stratum, the distribution area of the large pore channel is determined by using the oil deposit description result, the water absorption profile and other data, the area of the large pore channel is equal to B percent and is reflected in the injection and production well control area, the crude oil in the area of B percent is produced, the area contains a dominant seepage channel, the crude oil is basically displaced, the seepage fluid in the pore channel is water, and the crude oil in the area of (1-B percent) is not produced;

different α values correspond to different lower boundary curves, that is, different distribution regions of hypertonic strips, and for a non-five-point well pattern, the control region is determined by the midpoint of the connecting line of the left and right adjacent wells, and the area is marked as S₁The production level therein is still marked as B%, α corresponding to the lower boundary curve₁Satisfies the equation:

step 2, calculating the pore size distribution;

setting the reservoir to be n layers according to longitudinal heterogeneous, setting a certain time in the later stage of water injection exploitation, and determining the actual recovery ratio B of each layer by splitting according to the water absorption profile, the water absorption index and the liquid extraction index_i％，i＝1,2,…,n；

If the horizontal direction is not homogeneous, the flow water area roughly drawn on the ith layer is still marked as B_iSo that it contains sites of high permeability, the volume of which is equal to B of the total volume of the layer_iPercent; if there is no transverse heterogeneity, draw B_iB having an area equal to the total area of the layer_i% water-to-oil flow ratio of i-th layer

A_iIs the water content of the i-th layer of produced liquid, and

here K_io、μ_o、μ_w、B_i% is known, and the water phase permeability of the i-th layer at that time can be determined

Average radius of flooded pores of the layer

Wherein phi_iwPorosity of the injected water wave area; if K is Darcy, r is in centimeters, there is an approximation

The average pore diameter of the rest un-watered parts is

Note the book

I.e. lambda_iTable i ratio of pore radius at the water flowing area and the oil flowing area of the layer i, the pore radius obeys the log normal distribution and the approximate normal distribution

Wherein the standard deviation sigma io of the radius of the pore throat of the ith undisturbed stratum is calculated by the formula (11);

the radius of the channels can be divided into several stages as required,

the pore passage grading and the division standard thereof are determined according to the geological condition and the engineering requirement;

when no special consideration is given, the principle of aperture classification is that the probability that the apertures calculated by a majority of one-injection one-sampling control areas belong to each level is proper, and the situation that the probability of one or two levels is particularly high or particularly low is avoided;

subdividing a well group control area by using a three-dimensional grid and falling on a well group control area B_iPoint in (3) corresponds to pore throat radius

Wherein: sigma_iw＝λ_iσ_io(13)

Calculating r_iwThe probabilities belonging to the above classes are given by probability values of [0, 1%]The interval is divided into k subintervals, and the length corresponds to a probability value;

generating random numbers X uniformly distributed in the [0,1] interval, and if X falls in the kth subinterval, the pore throat radius at the point is the kth level, and the point is marked with a kth mark;

step 3, calculating the transverse heterogeneity of the flowing water area;

one injection and one extraction unit interval [0, R_e]Dividing into 100 equal parts;

each part area is regarded as the one-way flow of the incompressible fluid, and macroscopically, the flow of each part is different, and 100 parts of the incompressible fluid and the flow of each part macroscopically form the flow between one injection well and one production well; the flow formula of the jth part according to Darcy's law is

In the formula A_jThe J-th water cross-sectional area, m²；

K_j-permeability, md;

ΔP_j-the pressure difference, MPa, across the jth portion;

Q_jflow of the jth portion, m³/d；

L-length per fraction, well spacing R_e/100，m；

μ -viscosity, mPas;

a-unit correction factor, a-0.3858;

from this, the permeability at the j-th part can be obtained

Formula (15) shows that the permeability can be obtained for the known pressure difference, the known seepage cross-sectional area and the known flow rate, and the calculation method of the pressure difference, the known seepage cross-sectional area and the known flow rate is described below to obtain the permeability at each position;

1. calculation of flow

By monthly water uptake of injection well at layer j₁Monthly liquid production quantity Q of corresponding layer of production well₂The linear combination of (2) can determine the flow rate Q of the liquid in the i-th portion_i

2. Calculation of pressure at various locations

Injecting water into the well A, producing liquid from the well B, and determining the pressure of any point M of the stratum as

Wherein

Wherein r is₁-distance of point M to water injection well a;

r₂-distance of point M to production well B;

r_e-a feed radius;

r_w-a wellbore radius;

r is well spacing;

p_WA、p_WBinjecting water into the well A, producing liquid from the well B and the bottom pressure of the two wells;

3. method for determining cross-sectional area A

Let the circle with radius r and curve y be x^αIntersect at point (x, y) and solve the system of equations

The intersection coordinates (x, y) can be obtained, and β ═ tan can be obtained^-1(y/x) such that θ ═ pi/2-2 β, assuming reservoir thickness h, the cross-sectional area at radius r is

The cross-sectional areas A, Δ p and the flow rate Q_iSubstituting the equivalent value into a formula (15) to obtain the permeability K of the section with the radius r, and calculating the probability that the radius of the pore throat at the section belongs to each level by using the method in the previous section;

step 4, calculating the volume of each level of pore channel;

after the position and the size distribution of the large pore passage are quantitatively analyzed, the volume of each level of pore passage is calculated, and the calculation process of each level of pore passage is as follows: r_eIndicating the distance between the water injection well O and the oil production well W,

let a be the radius r of a circle and curve y^1-αx^αIntersect (x, y), solve the system of equations

To obtain (x)_r,y_r)，tgβ＝(x_r/a)^α-1，β＝tan^-1((x_r/a)^α-1)，θ＝π/2－2 β area of sector AOB S_AOB＝πθr²A 2, a straight line y xtg β and a curve y a^1-αx^αArea of enclosed pattern

The area of the large pore channel distribution area in a circle with the radius of r is

Let the distribution probability of the ultra-large pore channel, the middle pore channel and the small pore channel at the radius r be p respectively₁(r)，p₂(r)，p₃(r)，p₄(R) the interval [0, R ]_e]100 equal parts, with an interval R_eN, obtaining the volume of the grade i pore canal of the r part

Wherein,

S₀＝0

x_rby solving a system of equations

Obtaining;

step 5, simulation calculation of fractured reservoir

Calculating the permeability K and the porosity phi of each of 100 parts in the flowing water area, and then calculating the permeability K and the porosity phi according to a formula

Wherein b is_i-width of crack, mm;

-fracture permeability, D, of part i;

-fracture porosity of part i;

calculating the crack width b of the i-th part_iWherein the crack permeability of the ith part

Approximating K calculated by the original software_iInstead, this is because the fracture permeability is much greater than the matrix permeability, i.e., water is considered to have passed along the fracture;

while

Is measured data, and is determined by the following method in the case where there is no measured data

Firstly, fitting the porosity and permeability of three well groups according to the following formula;

φ＝αlnK+β

that is to say

K＝Ae^Bφ(28)

Wherein,k (mD), phi is the value of percent removal;

the relationship between fracture permeability and porosity can be represented by the following formula

K_f＝8.33×10⁶φ_fw²(29)

Wherein, w is the width of the crack, mm;

K_f-fracture permeability, D;

let aK equal to K_f(a is determined by the water cut, where a is taken to be approximately 0.5),then, by equations (28) and (29) and noting the dimensional change, it can be obtained

aAe^Bφ＝8.33×10⁵φ_fw²(30)

Note the book

Into formula (30)

The calculation formula of the known seam width w and the hole radius r is as follows

K in the formula (32) is crack permeability, and K in the formula (33) is high permeability strip permeability needing plugging regulation calculated according to a gap medium; because now

The pore size distribution calculated for the pore medium can be used for solving the gap width distribution of the crack medium, namely the percentage of the cracks with various gap widths; ratio of slot width to hole radius

Porosity of fracture medium

1% of the comprehensive porosity phi of the seepage medium provided by geological data, and the average seam width is 1.21 times of the average pore radius; the aperture division is limited to 3, 5 and 8, and the slit width is limited to 3.6, 6.1 and 9.7, namely the slit width range corresponding to each stage of cracks is as follows (mum):

micro-cracking: w is less than or equal to 3.6;

middle crack: w is more than or equal to 3.6 and less than or equal to 6.1;

wide crack: w is more than or equal to 6.1 and less than or equal to 9.7;

extra wide crack: w is more than or equal to 9.7;

according to the division standard, the calculation is carried out by using the method, and the volume and the percentage of each stage of fracture are listed in detail in a calculation result data table.

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